In August 2014, the U.S. Environmental Protection Agency ("EPA") lifted the suspension and proposed debarment, and removed the statutory disqualification, previously imposed on W&T Offshore, Inc by the EPA.

Increasing the 2014 capital expenditure budget by $185 million to $635 million which includes, among other things, three additional deepwater wells and acquisitions already completed.

Our wholly-owned subsidiary, W & T Energy VI, LLC, completed the acquisition of exploration and production properties in the deepwater of the Gulf of Mexico from Woodside Energy (USA) Inc., which included a 20% non-operated working interest in the producing Neptune Field (Atwater Valley blocks 574, 575 and 618 along with an interest in the associated tension leg platform) and all of its interest in 24 deepwater exploration blocks.

In June 2014, the U.S. Court of Appeals for the Fifth Circuit ruled in favor of W&T as we sought insurance recovery for our Removal of Wreck costs associated with damage resulting from Hurricane Ike. The underwriters subsequently requested a rehearing which was denied. The Company now expects to recover in excess of $46 million from the insurance underwriters.

In May 2014, we commenced drilling the Mississippi Canyon Block 782 "Dantzler" No. 2, a deepwater exploration well with the intent to identify additional field reserves beyond the significant discovery made by the Dantzler No. 1 well in 2013. We hold a 20% non-operated working interest in Dantzler.

We drilled two additional horizontal wells testing the Wolfcamp "B" formation at our Yellow Rose field in the Permian Basin of West Texas. Completion of those wells is underway. During the second quarter, we completed 11 vertical wells and one horizontal well. For the second quarter of 2014, production from the field averaged 4,379 Boe per day gross (3,375 Boe per day net to our interest).

At the end of the quarter, we were drilling two offshore shelf wells which were the A-16 at Ship Shoal 349 "Mahogany" and the A-2 ST at East Cameron 321. The EC 321 ST was successful and we are currently completing the well.

Production for the second quarter of 2014 averaged 48,300 barrels of oil equivalent ("Boe") per day (54% oil and liquids), and our average realized sales price was $99.92 per barrel for oil, $39.98 per barrel for natural gas liquids ("NGLs") and $4.62 per thousand cubic feet ("Mcf") for natural gas.

Revenues for the second quarter of 2014 were $263.0 million compared to $235.4 million in the second quarter of 2013. Oil and NGLs made up 78% of second quarter revenues.

Net income for the second quarter of 2014, excluding special items, was $18.3 million and earnings were $0.24 per share. This represents an increase of 30.5% and 33.3%, respectively, over the second quarter of 2013.

Adjusted EBITDA for the second quarter was $175.7 million, up $34.8 million over the second quarter of 2013 and the Adjusted EBITDA margin for the second quarter increased to 67%, up from 60% in the second quarter of 2013. For the first six months of 2014, our Adjusted EBITDA was $343.7 million, an increase of $30.3 million over the first half of 2013. Our Adjusted EBITDA margin was 66% for the first six months of 2014 compared to 63% for the second quarter of 2013.

Paid regular quarterly dividend of $0.10 per share during the second quarter.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "Second quarter production and our averaged realized sales price were much improved over the second quarter last year, as our focus on the production of oil and liquids continues to pay off. With the increase in production for each of the products that we produce and a higher realized sales price, we generated strong cash flow to help fund our substantial inventory of exploration and development opportunities. Recently, the second Dantzler well commenced drilling and we continue to be highly encouraged by the success we are having in the deepwater Gulf of Mexico. For the balance of the year, we will remain active in the deepwater with new wells being added to our 2014 plan. These include exploration wells the Ewing Bank 910, Medusa and Neptune Fields. In addition, development at Big Bend continues and first production from this 2012 deepwater discovery is still slated for the second half of next year. The proximity of Big Bend to the Dantzler field will allow us to leverage this development effort so Dantzler will benefit from the Big Bend production infrastructure. In terms of our onshore activities, we are increasing our 2014 horizontal drilling program with three additional wells at our Yellow Rose field in the Permian Basin of West Texas. Currently, two horizontal Wolfcamp "B" wells and one horizontal lower Spraberry well are being completed and will provide additional key data as we focus on optimizing our drilling and completion operations. The acquisition market also offers interesting opportunities, especially in the deepwater, and we remain active in pursuing transactions to acquire producing properties with substantial upside potential. Our recent purchase of deepwater properties from Woodside is representative of the type of transactions that meet our acquisition criteria. Between the new deepwater wells, the acquisitions that we have already completed and the horizontal prospectivity we see in West Texas, we are increasing our 2014 capital budget by $185 million," he said.

Production, Revenues and Price: For the second quarter of 2014, total production volumes were up 1.6 billion cubic feet equivalent ("Bcfe") or 6.6% (273,000 Boe) compared to 2013 with oil, natural gas and NGLs volumes all up over 2013. Production increases and higher oil volumes came from increased production from several fields including Mahogany and Matterhorn and from acquisition activities that brought production from the deepwater Medusa field (acquired in the fourth quarter of 2013) into our portfolio. Production volumes were not as robust as they could have been as we continue to be impacted by production deferrals, which for the second quarter were estimated at 564,400 Boe or 3.39 billion cubic feet ("Bcf") equivalent. Our most significant production issues being the continued shut-in at the non-operated Mississippi Canyon 506 "Wrigley" field.

Revenues for the second quarter of 2014 were $263.0 million compared to $235.4 million in the second quarter of 2013. During the second quarter of 2014, we sold approximately 1.9 million barrels of oil, 514,500 barrels of NGLs and 12.2 Bcf of natural gas as compared to approximately 1.7 million barrels of oil, 491,100 barrels of NGLs and 11.8 Bcf of natural gas during the same period in 2013. Our average realized sales price was $99.92 per barrel for oil, $39.98 per barrel for NGLs and $4.62 per Mcf for natural gas in the second quarter of 2014. On a combined basis, we sold 48,300 Boe per day at an average realized sales price of $59.63 per Boe compared to 45,300 Boe per day sold at an average realized sales price of $56.88 per Boe in the second quarter of 2013.

Cash Flow from Operating Activities and Adjusted EBITDA: EBITDA and Adjusted EBITDA are non-GAAP measures and are defined in the "Non-GAAP Financial Measures" section at the end of this news release.

Adjusted EBITDA for the second quarter of 2014 was $175.7 million which represents an increase of 24.7% over the $140.9 million reported for the second quarter of 2013. Adjusted EBITDA was higher for the second quarter of 2014 primarily due to a $27.6 million increase in revenues and a $6.5 million decrease in lease operating expenses. For the six months ended June 30, 2014, our Adjusted EBITDA was $343.7 million, an increase of $30.3 million over the first half of 2013. Our Adjusted EBITDA margin was 67% for the second quarter of 2014, up from 60% in the second quarter of 2013. Net cash provided by operating activities for the first half of 2014 was $271.1 million compared to $297.4 million from the same period in 2013. Cash flows from operating activities, before changes in working capital, were $298.8 million in the first six months of 2014, an increase of $23.2 million compared to the $275.6 million generated over the same time period in 2013. The change in working capital between those periods was a usage of $49.5 million.

At June 30, 2014, we had a cash balance of $23.8 million and $439.4 million of undrawn capacity available under the revolving bank credit facility, with a borrowing base of $750.0 million.

In June 2014, the U.S. Court of Appeals for the Fifth Circuit ruled in favor of W&T as we sought recovery for our Removal of Wreck costs associated with damage resulting from Hurricane Ike. The underwriters subsequently requested a rehearing which was denied. The Company now expects to recover in excess of $46 million from the insurance underwriters.

Lease Operating Expenses ("LOE"): LOE, which includes base LOE, insurance premiums, workovers, facilities expenses, and hurricane remediation costs net of insurance claims, was $61.8 million for the second quarter of this year down from $68.2 million reported in the second quarter of 2013. Base LOE increased $9.7 million, insurance premiums were lower by $1.2 million, workover costs decreased $16.2 million and facilities expense was higher by $1.2 million. The biggest single factor in the decrease in LOE was lower workover costs as the second quarter of 2013 included a rig workover at MP 69. There were no costs of this nature incurred during the second quarter of 2014. Base LOE increased with more downhole well work at our Yellow Rose field, higher expenses offshore, and increased contract labor. Insurance premiums were lower as coverage has improved while costs have come down, and facilities costs were up on higher activity offshore.

Depreciation, depletion, amortization and accretion ("DD&A"): DD&A, including accretion for asset retirement obligation, was $29.18 per Boe for the second quarter of 2014 up from $24.23 per Boe in the second quarter last year. On a nominal basis, DD&A was $128.2 million for the second quarter of 2014 versus $99.9 million in the second quarter of 2013. The DD&A rate and DD&A expense increased in part due to increases in the full cost pool from capital expenditures and estimated future development costs. The focus on deepwater exploration and development necessarily increases costs before increasing proved reserves leading to an increase in the DD&A rate.

General and Administrative Expenses ("G&A"): G&A was $19.7 million in the second quarter of 2014, down slightly from $19.9 million in the second quarter of 2013.

Derivatives: For the second quarter of 2014 our net derivative loss was $13.1 million and consisted of a realized loss of $9.7 million and an unrealized loss of $3.4 million. The derivative loss relates to the change in the fair value of our crude oil commodity derivatives as a result of changes in crude oil prices. Although the contracts relate to production for future periods, changes in the fair value for all open contracts are recorded at the end of the respective reporting periods. The second quarter of 2013 had a net gain of $12.8 million, comprised of a $1.9 million realized gain and a $10.9 million unrealized gain.

Income Taxes: Income tax expense was $5.3 million in the second quarter of 2014 compared to $12.4 million for the second quarter of 2013 due to lower pre-tax income. Our effective tax rate for the second quarter of 2014 was 34.9% only slightly below the federal statutory rate of 35% due to an adjustment to the estimated annualized effective tax rate. For the second quarter of 2013, our effective tax rate was 35.7% and differed from the federal statutory rate primarily as a result of state income taxes.

Net Income & EPS: Net income for the second quarter of 2014 was $9.8 million, or $0.13 per common share compared to $22.4 million or $0.29 per common share during the same period in 2013. Excluding special items (which are derivative gains and losses), net income for the second quarter of 2014 was $18.3 million, and earnings were $0.24 per common share. This represents an increase of 30.5% and 33.3%, respectively, over that reported in the second quarter of 2013. Earnings excluding special items were up due to an 11.7% increase in revenues and a 9.5% decrease in LOE, partially offset by higher DD&A. See the "Reconciliation of Net Income to Net Income Excluding Special Items" and related earnings per share, excluding special items in the table under "Non-GAAP Financial Information" at the back of this press release for a description of the special items.

Capital Expenditures Update: Our capital expenditures for the second quarter of 2014 were $171.0 million compared to $162.6 million for the same period in 2013. For the first six months of 2014, our capital expenditures were $266.0 million, which were down from $299.2 million spent in the first half of 2013. So far this year, capital expenditures for oil and gas properties consisted of $61.2 million for offshore exploration activities, $63.7 million for offshore development activities and $53.4 million for acquisitions of offshore properties. Onshore capital expenditures have consisted of $24.9 million for exploration activities and $41.7 million for development activities. In addition we have expended $21.1 million for seismic, leasehold, and other costs.

We have increased our capital expenditure budget for 2014 to $635 million. The increase takes into account three additional deepwater wells (including one at Neptune and the second Dantzler well), one well on the shelf, three additional horizontal wells in the Permian Basin and for acquisitions completed so far this year.

OPERATIONS UPDATE

Offshore Gulf of Mexico: The Company currently has four rigs running offshore with one rig drilling on the second deepwater Dantzler well, one rig drilling on the SB 3 well at Neptune, one rig drilling the A-16 well at our Mahogany field (Ship Shoal 349/359), and one rig drilling the A-2 ST at East Cameron 321.

Atwater Valley 575 "Neptune" Field (20% WI) (Deepwater)

The Neptune field is in the Atwater Valley blocks 574, 575 and 618 and the Neptune TLP is located in a water depth of 6,266 feet. After closing on the acquisition of properties from Woodside in late May 2014, we brought the Neptune Field production into our portfolio. The field is producing at a rate of over 9,700 Boe per day gross providing approximately 1,700 Boe per day net to W&T. A new well, the SB 3, spud recently and, if successful, can be brought on line almost immediately through the existing subsea flow-line system.

Mississippi Canyon 782 "Dantzler" Field (20% WI) (Deepwater)

The Dantzler No.1 well was a major discovery in 2013 and a second well, the Dantzler No. 2, has commenced drilling with the intent to identify additional field reserves and prove up additional productive acreage beyond what was identified in last year's highly successful No. 1 well. Production from the Dantzler field is anticipated to be on line sometime in 2016. We are planning to utilize the production infrastructure associated with the Big Bend field which will help in getting this field on line timely.

Mississippi Canyon 243 "Matterhorn" Field (100% WI) (Deepwater)

The A-5 well was drilled in the eastern portion of the Matterhorn field and brought on line in the first quarter this year producing over 1,200 Boe per day. The well was drilled as a water injection well but discovered over 200 feet of net vertical oil pay and was brought on line as an oil producer. We will be converting the well to its original intended purpose in the third quarter, which will serve to increase pressure in the reservoir and ultimately increase the reserve life and overall production from the field. A well similar to this in another larger reservoir is currently under study for the western portion of the field.

Mississippi Canyon 538 "Medusa" Field (15% WI) (Deepwater)

Our ownership in the Medusa field was acquired in late 2013. Current daily production net to W&T is approximately 900 Boe and is 85% oil. There are current plans to drill one to two new exploratory wells in the field with the first well expected to spud in late third or early fourth quarter of 2014 with the second well to follow thereafter.

Mississippi Canyon 698 "Big Bend" Field (20%WI) (Deepwater)

Development at Big Bend continues and first production from this 2012 discovery is still slated for the back half of 2015. Big Bend is located in over 7,000 feet of water and has the gross (100%) resource potential of 30 to 65 MMBoe (P75 – P25 case).

Ship Shoal 349 "Mahogany" Field (100% WI) (Shelf):

During the second quarter, the A-15 well was brought on production and achieved a peak production rate of approximately 1,075 Boe per day (83% liquids). The well had logged over 65 feet of measured depth pay in the "P" sand. In May, the A-6 well was successfully recompleted in the "N" sand. In early June, the A-16 well was spud and is targeting the "M", "N", and "O" sands logged in the A-14 well (that was completed in the newly discovered "T" sand). Production from the Mahogany field averaged 8,220 barrels per day, up from 6,988 barrels per day in the second quarter last year and is a significant contributor to the increase in revenues and production this year over last year.

East Cameron 321 Field (100% WI) (Shelf)

The EC321 field is situated 97 miles off the Louisiana coast in 225 feet of water. The A-2 ST exploration well has logged over 140 feet of potential pay in five zones and is currently being completed in the exploratory Lentic 1 sand. We currently anticipate that the well will be brought on line in October of this year with a target initial production rate of 850 Boe per day (60% oil).

East Cameron 338 Field (100% WI) (Shelf)

A recompletion operation was conducted on the A-3 well and placed back on line at a rate substantially above expectations. The well reached a peak rate in excess of 1,300 barrels per day in the later part of June and is still flowing approximately 1,000 barrels per day currently.

Onshore West Texas Permian basin Yellow Rose Field (100% WI)

During the second quarter, we completed 12 wells at our Yellow Rose Field, 11 of which were vertical and one was a horizontal well. As of the end of the second quarter of 2014, we had seven wells awaiting completion, four of which were vertical wells and three of which were horizontal wells. We are currently running three rigs in this field, with two dedicated to our vertical program and one to our horizontal program. Our first Wolfcamp "B", the Chablis 9H reached a peak rate of 549 Boe per day and averaged 342 Boe per day for 30 days post completion of the well. Our jointly operated horizontal Wolfcamp "B" well had a peak rate of 703 Boe per day. Adjusting for lateral length, these wells had very similar production characteristics.

Our latest horizontal Wolfcamp "B" wells are emphasizing frac and cost optimization strategies. Our second and third operated Wolfcamp "B" horizontal wells, the Chablis 13H and the Chablis 10H, have both been drilled from the same pad (development and cost optimization) and are also testing two different frac designs on these wells from the same pad as we continue to drive development optimizations. These two wells were just recently frac'd and are currently in flowback, have already cut oil and are being equipped with artificial lift in early August. We expect peak rates from these wells in the coming weeks to months and this program is anticipated to begin setting the stage for a continuous and expanded program into 2015.

Additionally, we have just drilled a third horizontal bench ("Lower Spraberry") in our Yellow Rose field to total depth and the well is currently being prepared for completion and frac operations in the Lower Spraberry horizon. We anticipate results on the Lower Spraberry horizontal during the fourth quarter of 2014. We are excited about this new bench and we continue to aggressively exploit and de-risk our upside reserve potential in the field. We have recently made the decision to expand our horizontal drilling program with additional wells in 2014. For the second quarter of 2014, production from the field averaged 4,379 Boe per day gross (3,375 Boe per day net to our interest) and we expect the rate to grow through the balance of the year.

We are also encouraged by the active and successful well results surrounding our West Texas acreage holdings by offset operators. We continue to expand and capitalize on adding value through JV (Joint Venture) arrangements with offset lease holders to synergistically optimize our collective holdings and to leverage capital efficiencies. We expect to continue our trend of onshore JV arrangements through 2014 and into 2015, depending on the opportunities that arise. Some of those expected JV's may also target newer horizontal benches as well.

Third Quarter and Full Year 2014 Outlook:

Our guidance for the third quarter and full year 2014 is provided in the table below and represents the Company's best estimate of the range of likely future results. It is affected by the factors described below in "Forward-Looking Statements." Our third quarter of 2014 production guidance includes known production outages, particularly at Matterhorn due to a shut in of a third party pipeline for an integrity test and for potential tropical storm downtime (approximately 1.5 Bcfe for storm downtime). We are also expecting an increase in LOE with planned workovers at three different offshore fields and a general increase in facility maintenance. The summer is normally a busier time for offshore work as the weather is typically better. One of the workovers relates to a field that we have increased our working interest in and are taking over operations. Once the well returns to service we anticipate additional production and an incremental increase in proved reserves.

Estimated Production

Third Quarter 2014

Prior Full-Year2014

Revised Full-Year2014

Oil and NGLs (MMBbls)

1.9 – 2.1

8.7 – 8.9

No change

Natural gas (Bcf)

9.4 – 10.4

47.0 – 48.4

No change

Total (Bcfe)

21.1 – 23.3

99.0 – 102.0

No change

Total (MMBoe)

3.5 – 3.9

16.5 – 17.0

No change

Operating Expenses($ in millions)

Third Quarter 2014

Prior Full-Year

2014

Revised Full-Year

2014

Lease operating expenses

$78– $86

$243 – $269

$254 – $282

Gathering, transportation & production taxes

$7 – $8

$25 – $28

$27 – $30

General and administrative

$23 – $25

$85 – $93

$87 – $95

Income tax rate (100% deferred)

36.5%

37%

36.5%

Conference Call Information: W&T will hold a conference call to discuss our financial and operational results on Thursday, August 7, 2014, at 9:30 a.m. Eastern Time. To participate, dial 719-325-2329 a few minutes before the call begins. The call will also be broadcast live over the Internet from the Company's website at www.wtoffshore.com. A replay of the conference call will be available approximately two hours after the end of the call until August 14, 2014, and may be accessed by calling 719-457-0820 and using the passcode 3356171#.

About W&T Offshore

W&T Offshore, Inc. is an independent oil and natural gas producer with operations offshore in the Gulf of Mexico and onshore in the Permian Basin of West Texas. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 66 offshore fields in federal and state waters (62 producing and four fields capable of producing). W&T currently has under lease approximately 1.2 million gross acres, including approximately 0.6 million gross acres on the Gulf of Mexico Shelf, approximately 0.6 million gross acres in the deepwater and approximately 50,000 gross acres onshore in Texas. A substantial majority of our daily production is derived from wells we operate offshore. For more information on W&T Offshore, please visit our website at www.wtoffshore.com.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. No assurance can be given, however, that these events will occur. These statements are subject to risks and uncertainties that could cause actual results to differ materially including, among other things, market conditions, oil and gas price volatility, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, competition, the success of our risk management activities, governmental regulations, uncertainties and other factors discussed in W&T Offshore's Annual Report on Form 10-K for the year ended December 31, 2013 and subsequent Form 10-Q reports found at www.sec.gov or at our website at www.wtoffshore.com under the Investor Relations section.

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Income (Loss)

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

(In thousands, except per share data)

Revenues

$

262,994

$

235,383

$

517,510

$

494,605

Operating costs and expenses:

Lease operating expenses

61,765

68,248

117,384

127,590

Gathering, transportation costs and production taxes

5,827

6,388

13,115

12,621

Depreciation, depletion, amortization and accretion

128,236

99,896

251,542

208,767

General and administrative expenses

19,682

19,868

43,270

40,955

Derivative (gain) loss

13,079

(12,840)

20,571

(9,473)

Total costs and expenses

228,589

181,560

445,882

380,460

Operating income

34,405

53,823

71,628

114,145

Interest expense:

Incurred

21,454

21,536

42,912

42,770

Capitalized

(2,159)

(2,532)

(4,231)

(4,964)

Income before income tax expense

15,110

34,819

32,947

76,339

Income tax expense

5,273

12,423

11,921

27,325

Net income

$

9,837

$

22,396

$

21,026

$

49,014

Basic and diluted earnings per common share

$

0.13

$

0.29

$

0.28

$

0.64

Weighted average common shares outstanding

75,605

75,223

75,581

75,215

Consolidated Cash Flow Information

Net cash provided by operating activities

$

152,560

$

127,528

$

271,050

$

297,362

Capital expenditures and acquisitions

170,976

162,587

266,043

299,213

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)

Three Months Ended

June 30,

Variance

2014

2013

Variance

Percentage(2)

Net sales volumes:

Oil (MBbls)

1,856

1,657

199

12.0%

NGL (MBbls)

514

491

23

4.7%

Oil and NGLs (MBbls)

2,370

2,148

222

10.3%

Natural gas (MMcf)

12,150

11,842

308

2.6%

Total oil and natural gas (MBoe)(1)

4,395

4,122

273

6.6%

Total oil and natural gas (MMcfe)(1)

26,371

24,733

1,638

6.6%

Average daily equivalent sales (MBoe/d)

48.3

45.3

3.0

6.6%

Average daily equivalent sales (MMcfe/d)

289.8

271.8

18.0

6.6%

Average realized sales prices:

Oil ($/Bbl)

$

99.92

$

101.78

$

(1.86)

-1.8%

NGLs ($/Bbl)

39.98

32.17

7.81

24.3%

Oil and NGLs ($/Bbl)

86.91

85.87

1.04

1.2%

Natural gas ($/Mcf)

4.62

4.22

0.40

9.5%

Barrel of oil equivalent ($/Boe)

59.63

56.88

2.75

4.8%

Natural gas equivalent ($/Mcfe)

9.94

9.48

0.46

4.9%

Average per Boe ($/Boe):

Lease operating expenses

$

14.05

$

16.56

$

(2.51)

-15.2%

Gathering and transportation costs and production taxes

1.33

1.55

(0.22)

-14.2%

Depreciation, depletion, amortization and accretion

29.18

24.23

4.95

20.4%

General and administrative expenses

4.48

4.82

(0.34)

-7.1%

Net cash provided by operating activities

34.71

30.94

3.77

12.2%

Adjusted EBITDA

39.98

34.18

5.80

17.0%

Average per Mcfe ($/Mcfe):

Lease operating expenses

$

2.34

$

2.76

$

(0.42)

-15.2%

Gathering and transportation costs and production taxes

0.22

0.26

(0.04)

-15.4%

Depreciation, depletion, amortization and accretion

4.86

4.04

0.82

20.3%

General and administrative expenses

0.75

0.80

(0.05)

-6.3%

Net cash provided by operating activities

5.79

5.16

0.63

12.2%

Adjusted EBITDA

6.66

5.70

0.96

16.8%

(1)

MMcfe and MBoe are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

(2)

Variance percentages are calculated using rounded figures and may result in slightly different figures for comparable data.

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)

Six Months Ended

June 30,

Variance

2014

2013

Variance

Percentage(2)

Net sales volumes:

Oil (MBbls)

3,588

3,501

87

2.5%

NGL (MBbls)

1,038

1,026

12

1.2%

Oil and NGLs (MBbls)

4,626

4,527

99

2.2%

Natural gas (MMcf)

24,768

24,562

206

0.8%

Total oil and natural gas (MBoe)(1)

8,754

8,621

133

1.5%

Total oil and natural gas (MMcfe)(1)

52,521

51,726

795

1.5%

Average daily equivalent sales (MBoe/d)

48.4

47.6

0.8

1.7%

Average daily equivalent sales (MMcfe/d)

290.2

285.8

4.4

1.5%

Average realized sales prices:

Oil ($/Bbl)

$

99.26

$

104.61

$

(5.35)

-5.1%

NGLs ($/Bbl)

39.11

33.26

5.85

17.6%

Oil and NGLs ($/Bbl)

85.77

88.43

(2.66)

-3.0%

Natural gas ($/Mcf)

4.82

3.78

1.04

27.5%

Barrel of oil equivalent ($/Boe)

58.97

57.22

1.75

3.1%

Natural gas equivalent ($/Mcfe)

9.83

9.54

0.29

3.0%

Average per Boe ($/Boe):

Lease operating expenses

$

13.41

$

14.80

$

(1.39)

-9.4%

Gathering and transportation costs and production taxes

1.50

1.46

0.04

2.7%

Depreciation, depletion, amortization and accretion

28.73

24.22

4.51

18.6%

General and administrative expenses

4.94

4.75

0.19

4.0%

Net cash provided by operating activities

30.96

34.49

(3.53)

-10.2%

Adjusted EBITDA

39.27

36.36

2.91

8.0%

Average per Mcfe ($/Mcfe):

Lease operating expenses

$

2.23

$

2.47

$

(0.24)

-9.7%

Gathering and transportation costs and production taxes

0.25

0.24

0.01

4.2%

Depreciation, depletion, amortization and accretion

4.79

4.04

0.75

18.6%

General and administrative expenses

0.82

0.79

0.03

3.8%

Net cash provided by operating activities

5.16

5.75

(0.59)

-10.3%

Adjusted EBITDA

6.54

6.06

0.48

7.9%

(1)

MMcfe and MBoe are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

(2)

Variance percentages are calculated using rounded figures and may result in slightly different figures for comparable data.

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(Unaudited)

June 30,

December 31,

2014

2013

(In thousands, except

share data)

Assets

Current assets:

Cash and cash equivalents

$

23,847

$

15,800

Receivables:

Oil and natural gas sales

94,417

96,752

Joint interest and other

26,584

27,984

Income taxes

120

3,120

Total receivables

121,121

127,856

Prepaid expenses and other assets

38,644

29,946

Total current assets

183,612

173,602

Property and equipment – at cost:

Oil and natural gas properties and equipment (full cost method, of which $122,713 at

issued and 75,656,558 outstanding at June 30, 2014; 78,460,872 issued and

75,591,699 outstanding at December 31, 2013

1

1

Additional paid-in capital

410,642

403,564

Retained earnings

166,911

161,212

Treasury stock, at cost

(24,167)

(24,167)

Total shareholders' equity

553,387

540,610

Total liabilities and shareholders' equity

$

2,549,772

$

2,507,302

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Unaudited)

Six Months Ended

June 30,

2014

2013

(In thousands)

Operating activities:

Net income

$

21,026

$

49,014

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion, amortization and accretion

251,542

208,767

Amortization of debt issuance costs and premium

366

910

Share-based compensation

7,644

4,950

Derivative loss (gain)

20,571

(9,473)

Cash payments on derivative settlements (realized)

(14,310)

(2,310)

Deferred income taxes

11,921

23,726

Asset retirement obligation settlements

(30,338)

(32,886)

Changes in operating assets and liabilities

2,628

54,664

Net cash provided by operating activities

271,050

297,362

Investing activities:

Acquisitions of property interests in oil and natural gas properties

(53,363)

-

Investment in oil and natural gas properties and equipment

(212,680)

(299,213)

Purchases of furniture, fixtures and other

(1,715)

(981)

Net cash used in investing activities

(267,758)

(300,194)

Financing activities:

Borrowings of long-term debt

220,000

252,000

Repayments of long-term debt

(200,000)

(239,000)

Dividends to shareholders

(15,129)

(12,795)

Other

(116)

(342)

Net cash provided by (used in) financing activities

4,755

(137)

Increase (decrease) in cash and cash equivalents

8,047

(2,969)

Cash and cash equivalents, beginning of period

15,800

12,245

Cash and cash equivalents, end of period

$

23,847

$

9,276

W&T OFFSHORE, INC. AND SUBSIDIARIESNon-GAAP Information

Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures are "Net Income Excluding Special Items," "EBITDA" and "Adjusted EBITDA." Our management uses these non-GAAP financial measures in its analysis of our performance. These disclosures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP performance measures which may be reported by other companies.

Reconciliation of Net Income to Net Income Excluding Special Items

"Net Income Excluding Special Items" does not include the derivative loss (gain) and associated tax effects. Net Income excluding special items is presented because the timing and amount of these items cannot be reasonably estimated and affect the comparability of operating results from period to period, and current periods to prior periods.

Three Months Ended

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

Net income

$

9,837

$

22,396

$

21,026

$

49,014

Derivative loss (gain)

13,079

(12,840)

20,571

(9,473)

Income tax adjustment for above items at statutory rate

(4,578)

4,494

(7,200)

3,316

Net income excluding special items

$

18,338

$

14,050

$

34,397

$

42,857

Basic and diluted earnings per common share, excluding special items

$

0.24

$

0.18

$

0.45

$

0.56

Reconciliation of Net Income to Adjusted EBITDA

We define EBITDA as net income plus income tax expense, net interest expense, depreciation, depletion, amortization, and accretion. Adjusted EBITDA excludes the loss (gain) related to our derivative contracts. We believe the presentation of EBITDA and Adjusted EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures. We believe this presentation is relevant and useful because it helps our investors understand our operating performance and makes it easier to compare our results with those of other companies that have different financing, capital and tax structures. EBITDA and Adjusted EBITDA should not be considered in isolation from or as a substitute for net income, as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. EBITDA and Adjusted EBITDA, as we calculate them, may not be comparable to EBITDA and Adjusted EBITDA measures reported by other companies. In addition, EBITDA and Adjusted EBITDA do not represent funds available for discretionary use. Adjusted EBITDA margin represents the ratio of Adjusted EBITDA to total revenues.

The following table presents a reconciliation of our consolidated net income to consolidated EBITDA and Adjusted EBITDA along with our Adjusted EBITDA margin.

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